1. Field of the Invention
The present invention relates generally to downhole completion and production devices for use in oil and gas wells and, more specifically, to an inflatable packer having an inflatable elastomeric sleeve carried on a metallic mandrel, the mandrel having an improved means for increasing the friction between the outer metallic surface thereof and the inflatable elastomeric sleeve.
2. Description of the Prior Art
Various downhole devices employ elastomeric components which move either axially or radially relative to a cooperating external metallic surface during completion and production operations. One example is the inflatable packer which includes a tubular mandrel covered by an inflatable elastomeric sleeve secured to the mandrel by a pair of axially spaced-apart rings. The elastomeric sleeve is normally reinforced by a reinforcing sheath, which includes a plurality of overlapping ribs connected between the rings. Valve means are provided in order to allow inflating fluid to pass between the exterior of the metallic mandrel and the internal surface of the elastomeric sleeve in order to inflate the sleeve into sealing contact with the well bore or casing. The LYNES unique inflatable elements have been recognized for over three decades in unique inflatable element designs. These products include the external casing packer, the production-injection packer and the inflatable drill stem test tools, all of which are based upon inflatable packer technology.
Typically, such inflatable packers isolate the annulus above the packer from the annulus below the packer and are only required to be of a length long enough to form an effective seal. In other cases, inflatable packers are used in well completion, including those packers adapted to be positioned adjacent the producing zone and inflated with cement. After the cement has set, the packer is perforated and the well is produced through the packer. Packers of this type tend to be many feet in length, i.e., from 10 to 40 feet or more in length, in order to seal against both the producing formation which is perforated and the formations above and below the producing formation. An example of a known inflatable packer of the above type is the LYNES XL ECP packer available from Baker Service Tools, a division of Baker Hughes Incorporated, Houston, Tex.
Thus, completion type inflatable packers of the above design are of a much greater length than the typical inflatable packer used in, e.g., drill stem testing. The central portion of the inflatable, elastomeric element of such packers is supported and reinforced by the bore hole. As a result, a reinforcing sheath is unnecessary in the central part of the inflatable elastomeric element. However, reinforcement is generally required at the ends of the inflatable elastomeric element in order to prevent the elastomeric sleeve from extruding past the attachment collars. As a result, the elastomeric sleeves of the completion type packers have previously been reinforced only at the ends adjacent the attachment collars.
One problem encountered with the prior art designs involves the running-in operation in which the inflatable packer is run into the desired location within the well bore. At times, the elastomeric sleeve contacts the bore-hole wall. This possibility of contact is particularly acute in the case of deviated well bores. As the elastomeric sleeve contacts the well bore during the insertion operation, frictional force is applied to the elastomeric sleeve, tending to move the sleeve with respect to the metallic mandrel. In the case of a short length inflatable packer with continuous reinforcing sheaths, the reinforcing sheath provides adequate stiffness to prevent axial movement due to frictional contact with the surrounding well bore. In the case of completion type packers of the type described above, where the elastomeric sleeve is 10 to 40 feet or more in length, the coefficient of friction between the surrounding well bore and sleeve typically exceeds the coefficient of friction between the elastomeric element and the metallic mandrel. As a result, the elastomeric sleeve can move with respect to the mandrel. This movement can cause thickening of the sleeve at the upper end of the inflatable packer and can deform outwardly the upper reinforcing material. In some cases, the movement of the sleeve along the mandrel can cause the diameter of the packer to become greater than that of the surrounding well bore, causing the packer to become stuck in one location.
U.S. Pat. No. 4,311,314 shows an inflatable packer having an inflatable sleeve mounted on a tubular mandrel that is covered with a gritty, material. The grit particles are bonded to the outer surface of the mandrel by a suitable binder, such as an epoxy resin. While coefficient of friction of the inflatable sleeve on the grit covered surface is greatly increased, the application of the epoxy treatment increases manufacturing time and cost.
U.S. Pat. No. 4,871,179 also shows an inflatable packer which includes a tubular mandrel and an inflatable sleeve which is secured between attachment collars about the mandrel exterior. The exterior surface of the mandrel underlying the sleeve is roughened to increase the coefficient of friction between the mandrel and the sleeve. The mandrel can be roughened, as by threading the mandrel with a tooth profile. While this technique effectively increases the coefficient of friction between the mandrel exterior and the interior of the inflatable, elastomeric element, the manufacturing steps involved are again time consuming and expensive.
Accordingly, it is an object of the present invention to provide an inflatable packer having a metallic mandrel and a surrounding elastomeric sleeve with a high coefficient of friction between the mandrel and inflatable sleeve.
Another object of the invention is to provide such an inflatable packer without greatly increasing manufacturing time or expense.